Q&A: Is produced water extinguishing the Permian?

By Staff | June 12, 2018

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With the recent rise oil prices, operators have been adding rigs and ramping up completions in the Permian Basin. However, persistent operational water challenges present a material risk to companies' future profitability and production.

A new study by Wood Mackenzie examines the current growing water situation in the Permian and models the combined impact rising water volumes and increasing water costs could have on future breakevens and oil production growth.

Ryan Duman, principal analyst with Wood Mackenzie's Lower 48 upstream team, said: "As operator activity continues to pick up in the Permian, we expect over 2 million barrels per day of oil supply growth over the next five years.

"While attainable, the list of operational risks grows too and the least appreciated of these is produced water,” he said. “The combination of rising volumes and higher disposal costs threaten to shift cost curves and pose a growing risk to oil production growth in the Permian."

The report models various scenarios of rising water cuts and growing water management costs and found in an “aggressive” future cost scenario, breakeven costs in the Midland and Delaware sub-plays could increase by $3 to $6 per barrel—potentially curbing the growth of future Permian oil supply by 400,000 barrels per day by 2025.

It’s something that is starting to creep into more IR data, earnings calls and general industry conversations that led us to really understand what this means from a commercial standpoint, especially given the rig count and surgent production in west Texas.

Can you tell us what your paper is about and what it covers?

With produced water, there’s been a lot of discussion on what operators can do to mitigate the risks and technologies out there. Some operators are highlighting the different benches in the Permian, having greater water cuts than others, and then ultimately the costs associated with it. Given the multifaceted approach to water, we wanted to focus in and understand what this could mean on a micro—a single-well—basis to those economics, but also to a macro level that came back to supply dates. What could this mean for the future for Permian supply potential? What we did was try to understand in the Delaware and Midland basins, what does produced water look like over time for the Wolf Camp and Bone Spring? What are the costs associated with this? What kind of risk does it pose?

Why is this a bigger problem in the Permian? Why the focus there? What’s different today?

It’s not a new issue and the Permian’s not a new basin region by any means. What’s different now it that unconventional development in the Permian doesn’t allow for the same water management practices. By that I mean if you’re drilling conventional wells, most of the produced water can be reinjected for water floods or EOR (enhanced oil recovery). Whereas now, the operators, many are testing some of the tertiary recovery techniques, but nothing’s being done on a wide scale.

What that results in for unconventional development then is that all the produced water either has to be disposed of, recycled or reused. In other basins, water is still something that needs to be watched out for, but the amount of water is nothing near what we’re seeing in the Permian. In the DJ (Basin) for example, water ratios might be 1:1. But what we’re seeing in the Delaware Basin especially is that water ratios are about 4:1; in some extreme cases 7:1 and in the worst cases, 10:1. So we’re just dealing with an unprecedented amount of water out in west Texas.

What does this mean when it comes to high water-handling costs? What are operators doing to address this and how does it impact their bottom line?

With water costs and water management practices, it’s incredibly variable right now in the Permian. Some operators take an incredibly proactive approach, building out infrastructure or regional water handling hubs. Some operators (are) implementing recycle and reuse technologies, doing stuff in a way that they can combine the basically treated flowback and use it in fracking operations. Not everyone is ahead of the curve, though. With water management costs all in, we see a range of about 50 cents per barrel to sourcing, transport, disposal. And then—if you do have recycle and reuse technologies on site—the biggest swing factor we’ve seen is how reliant an operator is on trucking. That can be the biggest factor pushing those costs higher.

And so it’s not just a matter of the amount of water being produced in the Permian and the fact that it’s increasing over time, but also, how high are those costs associated with handling it? What we found is that as you go through the life of the well and the oil production moves to stripper well values, those costs don’t actually get to a point where you render anything sub-economic. But the costs in the high cases can impact breakeven economics by about $6 a barrel. So it’s definitely a meaningful amount.